For the past several years, automated drilling has promised to deliver major improvements in drilling performance. But the technology is facing new obstacles that might affect its progress and commercialization. Global oil prices and an ongoing gas glut have upturned the economics of automated projects, while in North America, human-operated drilling has improved substantially.
For Shell, those factors have caused it to scale back or cancel several projects in which automated drilling was to play a key role in the development of thousands of wells. This comes after years of headway the company was making with automated technology. In 2011, Drilling Contractor reported that the first generation of Shell’s automated control system had already shown a 70% improvement in rate of penetration (ROP) in areas where the company was testing the system. However, that figure is no longer relevant as human drillers in the US have narrowed the gap.
“What has happened is instead of competing against the average driller in an environment of high activity and scarcity, we are now competing against a pool of extremely talented and accomplished drillers,” said Mark Anderson, manager of drilling mechanics technologies at Shell. “Thus, the bar has been raised for the adoption of drilling automation-type technologies.”
Globally, however, there remains significant shortcomings in the capabilities and availability of rig crews, which underpin the need to deliver automation in the near future. Whether the goal is met rests on the shoulders of a small group of early adopters and innovators. If successful, their work will bring about a major departure from how drilling systems are designed and operated today by proving that, with data and algorithms in the driller’s seat, drilling can be made safer, more consistent, and ultimately cheaper by way of reducing nonproductive time (NPT).
Some experts foresee a generation of rigs that will operate mostly autonomously. Others predict that in the near future, it is more likely that rigs will be remotely controlled by drillers, geologists, and engineers working, not in the field, but in office buildings and on several wells at once. Some of the systems evolving now aim to turn drillers and rigs into something resembling today’s commercial airliners, whereby many functions of the airplane are automated with pilots able to take control if they need to.
The latter premise does not involve creating new fleets of rigs, but retrofitting them with highly advanced computer programs that use real-time data coupled with mechanized equipment to help increase the ROP and maintain wellbore stability. Two of the most recent examples of commercial technologies were developed by members of SPE’s Drilling Systems Automation Technical Section (DSATS).
Last year, ConocoPhillips and National Oilwell Varco (NOV) completed a pilot program in Texas to test a new automated system, which reduced drilling time by more than 40%. Since the pilot, the technology has expanded to North Dakota, and will soon be used in the North Sea, and may be introduced in the Middle East by year’s end.
For Tony Pink, vice president of NOV’s dynamic drilling solutions and services business, the automated system is an answer to US shale producers and other companies that desperately need to lower their break-even cost of production to cope with low oil prices. “This technology could make some [projects] that are struggling today become economic again,” he said. “If the cost per barrel is USD 55, we are effectively knocking USD 8 off that cost per barrel.”
Also last year, Norwegian software firm Sekal installed an automated program called DrillTronics on an offshore drilling platform operated by Statoil in the North Sea to speed up tripping and connection times. The program has been under development for decades and works by controlling torque, pump pressure, and hook load.
“The basic principle is to have protection of the well, your string, and downhole equipment using process models and automation built on top of that,” said Fionn Iversen, chief scientist at the International Research Institute of Stavanger (IRIS), who was on the team that developed DrillTronics.
However, the wider effort to reach a brave new world of automated drilling will have to clear many hurdles before it gains wide acceptance. Skeptics say the complexities involved with drilling miles into the subsurface will always necessitate a large degree of human control and intervention. There are just too many unforeseen events, they argue, to calculate or predict efficiently.
Even those who wholeheartedly support automated drilling say the industry is so fragmented that it makes building the business case harder than building the technology. And as with any new technology, “crossing the chasm” means automated systems must first prove that they offer a substantial benefit—which has been a tall order so far.
“What is the business value of doing this? And it is very hard to answer that question for drilling,” said John de Wardt, president of De Wardt and Company and the manager of the industry initiative to develop a technology road map for drilling systems automation. “There are compelling reasons right now for small segments of automation, but no one has been able to come out and articulate a compelling value reason,” for a fully automated system.
The Critical Perspective
Not everyone believes that automated drilling systems are going to be good enough to take into account and offset the myriad of factors that need to be managed to maximize rate of penetration (ROP) and prevent nonproductive time or costly stuck-pipe events.
Fred Dupriest, a professor of engineering practice at Texas A&M University, said there is a chance that the technology may someday achieve such capability, but is concerned that the current path that developers are taking will not work out anytime soon.
“My opinion is that there is hope, but there is something else we need to do,” he said. “What I am pushing for today, as opposed to 10 years ago, is that industry needs to be aware that you can’t unilaterally automate one factor, or what I would call a performance limiter.”
Dupriest is referencing current attempts to automate drilling control systems involving key operations such as rotary speed, weight on bit, or hydraulics. He said while those are achievable objectives, the major challenge is that the majority of footage being drilled today is now constrained by performance limiters that most automated systems do not control, such as wellbore instability or hole cleaning.
If automation can solve major drilling problems instead of just increasing ROP, Dupriest sees more opportunity for the technology to enjoy successful commercialization.
Before retiring from ExxonMobil where he worked for 36 years, Dupriest led efforts to improve drilling performance by monitoring and interpreting something known as mechanical specific energy. Doing this gives engineers and drillers the ability to see and react to bit dysfunction in real time and improve rock-cutting performance.
Using this methodology, ExxonMobil developed the Fast Drill Process that was used to set industry drilling records in distance and speed. Though he noted that such results are hard for other companies to replicate with different business models, Dupriest said he still does not foresee automation trumping proper training and education in drilling physics soon.
While computers are most definitely involved in this physics-based approach, Dupriest said a driller and an engineer equipped with the knowledge of drilling physics will outcompete any automation system. That is because human drillers are able to avoid problems on the fly and then re-engineer the next bit trip or the next well based on their experience. “And automation won’t do that; it will constrain you,” he said. “It has the ability to give you average, or slightly above average, drilling performance.”
The most recent challenge is the global downturn in oil prices that have resulted in industrywide reductions of capital spending. Rig contractors have been hit especially hard after enjoying several years of strong demand for units with automation, most of which include systems on the rig floor and not the downhole side, for both onshore and offshore drilling.
Andrew Meyers, a manager with Douglas-Westwood who studies both the onshore and offshore market, said the downward pressure on day rates and a dampened desire from operators to pay premiums for the latest generation of rigs is expected to slow automation uptake. “Adding new rigs with automation is not likely here in the next few years,” he said.
Meyers continued, “There are more high-spec rigs available in the onshore market currently, so the operators should have access to something more automated, but there is not going to be this dynamic of encouraging drilling contractors to build more automated rigs in this environment because there is less value for them. They are going to be spending little money on their assets in this down cycle.”
Amid the evaporation of US rig demand, downhole automated systems continue to improve but remain “at the embryonic stage of the maturity curve,” according to Luca Brutti, a senior consultant at OTM Consulting and an ex-Schlumberger engineer. Based on his observations of industry trends, the technology will achieve critical mass once enough companies prove it works.
“The signs are there, it is just a matter of time. I can see operators taking interest in what the others are doing,” he said, and added that the shortlist of companies being watched include Statoil, Shell, and Saudi Aramco. “There is going to be a moment when the transition happens. Suddenly, everyone is going to start talking about it and all it needs is a number of success stories to be showcased.”
Automated Well Construction
Last August, in the Eagle Ford Shale play of south Texas, NOV and ConocoPhillips wrapped up a nearly yearlong automation experiment involving 10 horizontally drilled wells about 12,000 ft deep with 6,500-ft-long laterals. The work started by drilling four wells without using any automation to establish baseline benchmarks. The remaining six wells were drilled using an automated package comprising three individual systems that relied on the integration of high-speed data by
- A surface stick/slip mitigation device
- A downhole weight-on-bit controller
- An autodriller to visualize the data for humans and minimize vibrations
The work was done using one of ConocoPhillips’ lower-performing rigs; with NOV’s system, the final well was drilled to the bottom in just over 4 days. The average drilling time of the six wells was about 6½ days. Compared with the four benchmark wells, this translated into a 37% reduction in drilling time, and 43% when factoring in a reduction of NPT since there were no tool failures or safety incidents involved with the automated drilling.
Serving as the nerve system for the different components is the wired drillpipe, which sends large amounts of data from downhole measurement units back to the rig in real time. Without wired pipe, this level of automation would not be possible with mud pulse telemetry since it is incapable of high-speed data delivery. One of the major learnings realized by the drillers through the use of wired pipe was their weight on bit (WOB) as measured from the surface was off by 50%.
Based on what the downhole data was telling them, the WOB was increased far more than what the drillers had previously thought was acceptable and as a result, the operations saw a much improved ROP. One of the main objectives of the automated system, as described in the technical paper that outlined the case study (SPE/IADC 173159), was to drill more aggressively than what conservative safety margins dictated. Typically, drillers err on the side of caution to prevent damage to downhole equipment and ensure wellbore stability.
The automated stick/slip mitigation system also provided the drillers with more energy to apply to the bit by preventing the drillstring from banging around in the wellbore. The third component, the visualization and vibration minimizer, told the driller that the activity happening thousands of feet downhole was providing a stable downhole environment. If the drilling is causing a problem, then the same system provides immediate notification.
Since the ConocoPhillips pilot, Hess is now using the NOV system commercially on a rig in North Dakota’s Bakken Shale, Pink said. Total is in the process of installing the system on one of its offshore rigs operating in the North Sea and by late this year or early next year, NOV expects to have the system working in the Middle East for Saudi Aramco. Other operators, including ConocoPhillips, are in the process of analyzing their US unconventional assets to find areas where the system will deliver the most value.
The idea of NOV’s automated drilling system was sparked at a DSATS workshop in Paris in 2011. Based on the need expressed by operators, the leadership at NOV decided to go full steam ahead. “Three-and-a-half years from an idea to a commercial product is actually pretty fast,” Pink said. “The challenge now is how quickly can it go from being run on two or three rigs, to where it really delivers value for our industry on 50 or 100 rigs?”
He estimated that if a rig experiences an average of 30% reduction in time from spud to total depth using NOV’s system, then the expected savings on overall drilling costs, including completion and hydraulic fracturing, could be around 15%. Based on early stage results, Pink said the performance improvements have proven to be repeatable and should translate to drillers of any level of expertise.
“If you look at an average rig crew, typically, we see the lower performers are lifted up very quickly to the performance of the best rig crews,” he said. “But the top drillers get value too—a rising tide lifts all boats.”
Pink noted that in the US and around the world, many drillers are about half the age of those working when he entered the business. But when these younger drillers use automated downhole tools and visual systems, he said, “They have become much more like a pilot flying that rig,” and are also able to learn quickly and perform at a higher standard than they would without this technology.
One important thing that separates NOV’s automated control system from others is that it was developed using an open platform that enables clients and other companies to build apps for it. This approach takes a page from Apple’s iPhone and iPad model, whereby anyone with the smarts to develop an app that can make use of the drilling data to interface with a rig’s control system is welcome to do so. The only apps available right now are ones that NOV has developed, although it is working with operators to explore how they can build their own.
Of course, it also requires allowing people to peer deep inside NOV’s proprietary technology. “That is not an easy thing to do, but that is our long-term strategy,” Pink said. “If we make sure the platform is open to anyone out there writing apps for our system, it inherently makes the system more valuable.”
An Industry First
One of the latest milestones for automation based on modeling comes from Sekal, which said last October that DrillTronics was the world’s first automated drilling system used on a commercial well. The modeling and control system was installed on Statoil’s Statfjord C drilling platform in the North Sea, where it successfully improved connection times and allowed for more efficient tripping.
DrillTronics achieves speed and safety by setting thresholds based on the driller’s confidence margin and calculations that continuously update based on the drilling data sent up the borehole. Iversen of IRIS, also a committee member of DSATS, hopes that DrillTronics will evolve into a system that operators use to reach reservoirs that otherwise would be impossible or too unsafe to access. “That is where the really huge value is,” he said.
When used in the passive mode, the program is merely advising the driller on safe limits. In the active mode, or automated mode, if the limits are exceeded, automatic reactions are prompted. “These constraints are enforced physically, so the driller cannot exceed them,” he said. “As long as the driller is within those bounds, he is allowed to do what he likes.”
Since the system monitors downhole conditions in real time, it can also provide advanced warnings of danger when unexpected events occur that do not correspond with the drilling model, such as a buildup in pressure. When such events take place, DrillTronics can shut down the drilling operation. “This is the system reacting, taking over for the driller and helping the driller avoid a more serious situation,” Iversen said.
In addition to safety triggers, other automated sequences may be programmed, such as pump starts and friction tests. The company is working on automating other sequences, such as hole cleaning which will help prevent a stuck pipe.
In development since 2001, DrillTronics is one of the most sophisticated automated systems of its kind on the market; however, it is not a fully automated system. And Iversen said it need not be. “I am not sure we will get to the stage where all drilling rigs are as automated as technology allows, but definitely there is a demand for a higher level of automation to achieve the drilling of more complex wells,” he said.
To gain acceptance, Iversen said keeping humans in the loop will be important and that when looking at various levels of automation, the key question is what is really needed. “I do not think there is one answer to that,” he said. “But if you have a very challenging well with narrow margins, and you want to be able to drill it, then perhaps a higher level of automation is required.”
Down Prices Affecting Uptake
Shell once had big plans for factory mode drilling using dozens of automated rigs in unconventional fields in China, Australia, Canada, and the US. Today, most of the plans are on hold indefinitely after Shell sought to cut capital spending. The company’s grand vision for automation was driven by its need to drill thousands of wells with similar designs, and to do so as cheaply as possible.
The problem was twofold. In some project areas, Shell foresaw a shortage of skilled labor. Additionally, the sophisticated directional drilling systems needed were too costly to justify. To design and build technology that would become cheaper with economies of scale, Shell formed a 50/50 joint venture with China National Petroleum Corp. called Sirius Well Manufacturing Services.
The plan was for Sirius to develop innovative equipment and new well designs that lend themselves to automated drilling and other completion tasks such as cementing. A major component of the Sirius program involved Shell’s in-house developed drilling control system known as ScadaDrill.
Described as an “intelligent autodriller” that takes over the driller’s joysticks, ScadaDrill was introduced in 2009 and has been used to drill selected well sections with the ultimate goal of expanding its capability to drill entire wells. Less mature systems are under development to automate directional drilling, connection operations, and tripping in and out of the well.
However, in the years since Sirius’ brand of automated well manufacturing was conceived, the emergence of cheap and abundant supplies of natural gas in the US, coupled with the more recent halving of global oil prices, has altered the destiny of capital-intensive projects around the world.
While Sirius has provided limited drilling and completion services in China and Australia, the company has undertaken its only major well manufacturing at Carmon Creek in Alberta, Canada. Fully operated by Shell, the project will produce 80,000 B/D of heavy oil from tightly spaced wells at full capacity. The first phase of the program got under way in late 2013 using automated rigs to drill more than 600 wells on 13 pad sites. First production is expected this year and the second phase is expected to be completed by 2018.
But in January, Shell announced that it is canceling the final two phases of the project as part of its 3-year plan to reduce spending by USD 15 billion. The company also scrapped its plans to use Sirius’ rigs for drilling coalbed methane wells in Australia for a major liquefied natural gas project and shale projects in China.
The Road Map to Automation
John de Wardt, president of De Wardt & Company and program manager of the Drilling Systems Automation Roadmap cross-industry initiative, has been working for the past few years with other experts to develop a comprehensive technology road map for automation.
He is also a board member of SPE’s Drilling Systems Automation Technical Section (DSATS), formed to drive the development of automated well construction technologies. Based on his work with these groups, he expects that a series of breakthroughs in the next few years will lead to a full embrace of automated drilling systems in the next decade.
“It is easy to look at it and say it is a nice pipe dream. But then when I discuss with people what is actually happening out there, I see data points that verify this is a realistic vision,” said de Wardt. The road map is a guide that companies in the industry may follow to go from automated components, or subsystems, such as bottomhole assemblies or weight on bit controllers, to a fully automated drilling system.
While it may be a slow piecemeal approach, de Wardt said such a plan is needed to coordinate the complex ecosystem of companies involved with well construction. The industry reality is that it takes an amalgamation of equipment manufacturers, rig contractors, and service companies to drill wells for operators. A few majors, such as Shell, national oil companies, and integrated project management companies that own rigs may have such prowess but they are the exceptions.
“I think it will go both ways because there will be some integrators that are going to see the value in doing it from the top down,” he said. “But independents are not going to go out and spend big on this; they are not going to go out and fund such a change like that.”
One stop on the road map involves standardization. Using the Internet as an example, de Wardt said different automated systems need a common protocol so they can “talk” to each other and a control system, regardless of who made them. For instance, the work that DSATS is undertaking and the application developed by NOV using an open platform.
On how automation creates value, de Wardt offers an example from the mining industry. When Rio Tinto, a London-based mining company, sought to transform one of its largest mines in Australia into a completely autonomous operation, it was able to do so relatively quickly, thanks to some inherent advantages of its business structure.
The company owns the mine along with all of the equipment and vehicles used to operate it. So it worked with the equipment manufacturers to automate each machine, developed a remote control center, and then automated the train that takes the ore more than 800 miles to its wharf facility. Trials to autonomous operations took 5 years and as a result, some elements of production increased by 30%.
Another example involved applying automation and a remote control center to create an autonomous container wharf operation. De Wardt said the wharf operator saw a reduction of 27% in maintenance, a decrease of 22% in fuel consumption, an increase of 18% in productivity, and a drop of 33% in labor costs. While not a true apples-to-apples comparison, de Wardt said such numbers provide a basis for savings, and thus reveal an idea of the potential value creation that oil and gas companies stand to realize.
“It is not going to make these huge differences by doubling productivity or more, because you should’ve done some of that with your human resources,” he said. “But if my downhole system automatically changes itself to get out of large vibrations and shocks, and into low vibrations and shocks … and did it all the time, it is going to save you money.”
When Talking Automation, Mind the Algorithms
The word “automation” is a catchall for a detailed set of levels of control; 10 in fact. And each will be applied in a different way. As each system climbs the scale, one rung at a time, pushing it up will be increasingly accurate algorithms and computer models.
According to robotics pioneer Thomas Sheridan’s levels of automation, at the most base level, systems are simply advisers with no control whatsoever. Toward the middle of the scale, humans take on more of a supervisory role, or as some phrase it, “are kept in the loop.” The highest level involves automated systems that ask for no help from humans while doing their tasks, and actually ignore them, with the exception of override systems to initiate emergency shutdowns.
“Once we get to the point where there is full automation, there are going to be some exciting and radical new changes that take place,” said John Hedengren, an assistant professor of chemical engineering at Brigham Young University, who leads a research team on drilling automation and works with SPE’s Drilling Systems Automation Technical Section (DSATS) on data quality assurance for automation.
Hedengren underscores his optimism for what is yet to come by citing Moore’s Law, which has astutely predicted the exponential improvements seen in computer processing over the past half century. In the last 15 years, Hedengren said computing speed has increased by 1,000 times, while in the same time span, some of the algorithms for drilling optimization have also improved by 1,000 times. “If you put those two together, it is actually a million times faster to run some of the same problems that we were running just 15 years ago,” he said.
For automation, it means what was impossible to do even 5 years ago is achievable today by the convergence of advanced computing technology and advanced measuring devices that feed drilling information into the models for constant readjustments.
Hedengren said with this development, the upstream industry is moving closer to “on the fly” well design. This will be possible through the use of improved sensors, wired pipe, and more sophisticated algorithms that enable surface drilling equipment to control stick/slip, whirl, and other issues that slow down drilling. “The critical thing with modeling and automation is that we can take that real-time information and then adjust parameters to ultimately complete the well faster and with more productivity,” he said.
As the necessary precursors to automation, the majority of the drilling models and simulations must still be improved and in a big way. However, the industry has no benchmark or testing standards for the algorithms used in the models and simulations available on the market. Hedengren said that the solution is at least a couple of years away.
“There is a deep divide between good ideas and actual practice,” he said. “To be able to get from one side to the other, you’ve got to have these stepping stones, like bench mark models, data validation, field trials, and maybe a test rig trial as well.”
Bodies such as DSATS will have a role in defining the standards, Hedengren said. But until they do, companies are left to their own devices for determining which models and simulations to use for automated operations.
In one case, Hedengren said, a major operator spent years evaluating commercially available models and simulations before choosing a solution to move forward with. This glacial decision making is just one example of how the automation sector has been held back in years past because of a lack of standards for the validation of simulation results.
